1. Field of the Invention
The invention is related generally to the field of interpretation of reservoir monitoring using time-lapse seismic measurements. More specifically, the invention is related to methods for monitoring of reservoirs comprising laminated rocks.
2. Background of the Art
As is well known to geophysicists a sound source, at or near the surface of the earth, is caused periodically to inject an acoustic wavefield into the earth at each of a plurality of regularly-spaced survey stations. The wavefield radiates in all directions to insonify the subsurface earth formations whence it is reflected back to be received by seismic sensors located at designated stations at or near the surface of the earth. The seismic sensors convert the mechanical earth motions, due to the reflected wavefield, to electrical signals. The resulting electrical signals are transmitted over a signal-transmission link of any desired type, to instrumentation, usually digital, where the seismic data signals are archivally stored for later processing. The travel-time lapse between the emission of a wavefield by a source and its reception by a receiver after reflection, is a measure of the depths of the respective reflecting earth formations.
The seismic survey stations are preferably distributed in a regular grid over an area of interest with inter-station spacings on the order of 25 meters. The processed seismic data associated with a single receiver are customarily presented as a one-dimensional time scale recording displaying rock layer reflection amplitudes as a function of two-way wavefield travel time. A plurality of seismic traces from a plurality of receivers sequentially distributed along a line of survey may be formatted side-by-side to form an analog of a cross section of the earth. Seismic sections from a plurality of intersecting lines of survey distributed over an area of interest would provide data for three-dimensional representation of a subsurface volume of the earth.
Wavefield reflection from a subsurface interface depends on the acoustic characteristics of the rock layers that define that interface such as density and wavefield propagation velocity. In turn those characteristics depend inter alia on the rock type, rock permeability and porosity, fluid content and fluid composition. In a subsurface reservoir, a fluid transition or interface between gas and oil, or oil and water may act as a weak reflecting surface to generate the so-called bright spots sometimes seen on seismic cross sections. It is reasonable to expect that a change in the level or the characteristics of the reservoir fluids will create a change in the seismic signature associated with the reservoir. Thus, time-lapse or 4-D seismic data acquisition, that is, the act of monitoring the regional seismic signature of a reservoir over a long period of time would assist in tracking the depletion of the reservoir or the advance of thermal front in a steam-flooding operation.
Wason (U.S. Pat. No. 4,969,130) discloses a system of monitoring the fluid contents of a petroleum reservoir, wherein a reservoir model is employed to predict the fluid flow in the reservoir, includes a check on the reservoir model by comparison of synthetic seismograms with the observed seismic data. If the synthetic output predicted by the model agrees with the observed seismic data, then it can be assumed that the reservoir model correctly represents the reservoir. If not then the reservoir model, in particular its reservoir description, is updated until it predicts the observed seismic response. The seismic survey may be periodically repeated during the productive life of the reservoir and the technique used to update the reservoir model so as to ensure that the revised reservoir description predicts the observed changes in the seismic data and hence reflects the current status of fluid saturations.
Laurent (U.S. Pat. No. 5,724,311) discloses a method of monitoring of underground reservoirs. Seismic sources and receivers are installed in a fixed position on the production site, so as to have time stable operating conditions of identical source and receiver characteristics. A plurality of seismic sources are positioned at the surface or buried beneath the surface, on either side of a production well, and at least one array of receivers are positioned at the surface or in at least one well. Explosive sources, hydraulic sources, or electromechanical sources, etc, can be used. The seismic reflection from the underground reservoirs changes with time due to changes in the reservoir conditions such as fluid saturation.
Reimers et al. (U.S. Pat. No. 6,253,848) having the same assignee as the present application teaches the use of permanently installed sensors in a plurality of wellbores for reservoir monitoring. The source(s) may be at the surface or in a wellbore, and both seismic reflection as well as seismic transmission tomographic methods may be used for monitoring reservoir changes.
In reservoir monitoring, two properties that are of considerable interest are the fluid saturation and the pressure of the reservoir. Fluid saturation affects seismic data because of changes in the impedance of the reservoir when one fluid is partially or fully replaced by another fluid. This could be the replacement of heavy oil by steam in a secondary recovery operation, replacement of gas by water or oil in a gas reservoir, replacement of oil by water in an oil reservoir, etc.
When a rock is loaded under an increment of compression, such as from a passing seismic wave, an increment in pore pressure occurs which resists the compression and therefore stiffens the rock. In a classic paper, Gassman predicts the increase in effective modulus of a saturated rock by the following relations:                                                         K              sat                                                      K                0                            -                              K                sat                                              =                                                    K                dry                                                              K                  0                                -                                  K                  dry                                                      +                                          K                fl                                            φ                ⁡                                  (                                                            K                      0                                        -                                          K                      fl                                                        )                                                                    ,                  xe2x80x83                ⁢                              μ            sat                    =                      μ            dry                                              (        1        )            
where
Kdry=effective bulk modulus of dry rock,
Ksat=effective bulk modulus of the rock with pore fluid
Kfl=effective bulk modulus of the fluid
K0=bulk modulus of mineral material making up rock
xcfx86=porosity
xcexcdry=effective shear modulus of dry rock
xcexcsat=effective shear modulus of rock with pore fluid.
The relationships given be Gassman are valid in the low frequency limit.
Biot used a model incorporating mechanisms of viscous and inertial interactions between the fluid and the rock matrix and came up with a similar result in the low frequency limit. The results derived by Biot are frequency dependent and include a coupling coefficient between the fluid and the rock as well as a term related to the tortuosity of the fluid paths within the rock matrix.
Prior art methods for interpretation of seismic reflection amplitude changes in a reservoir have generally relied on eq. (1). If the matrix and fluid properties are known, then from a knowledge of the compressional and shear velocities for a first fluid saturation, all the terms in eq. (1) can be determined. A change in seismic reflectivity over time is used to determine a change in velocities and hence the fluid saturation. A commonly used method relies on the Amplitude-versus-offset (AVO] variation of reflection seismic amplitudes for compressional and/or shear wave data, generally described by Zoeppritz""s equations. The AVO effects are measured and based on an initial knowledge of the elastic modulii of the rock and its constituent fluids. Modeling results using the Gassman and Zoeppritz equations are used to derive the fluid saturation.
In addition to the fluid saturation effects, it is well known that elastic modulii of rocks are dependent upon the effective stress. The effective stress is defined as the difference between the overburden stress and the formation fluid pressure. As the reservoir is depleted, the formation fluid pressure drops so that the effective stress and the elastic modulii of the rocks increases. Landro (Geophysics, vol. 66, No. 3, pp 836-844), the contents of which are incorporated herein by reference, derives explicit expressions for computing saturation-and pressure-related changes from time-lapse seismic data. As a simplification to fitting the AVO behavior over a range of offsets, input is near-and far-offset stacks for the baseline seismic survey and the repeat survey. Landro shows that the method is successful in a segment where pressure measurements in two wells verify a pore- pressure increase of 5 to 6 MPa between the baseline survey and the monitor survey. The estimated saturation changes also agree well with observed changes, apart from some areas in the water zone that are mapped as being exposed to saturation changes (which is unlikely).
A significant number of hydrocarbon reservoirs include deep water turbidite deposits that consist of thin bedded, laminated sands and shales. In such reservoirs, the wavelengths of seismic signals is much larger than the layer thicknesses. For example, with a frequency of 50 Hz and a velocity of 5 km/s, the wavelength for a compressional wave is 100 m. This is much longer than layer thicknesses commonly encountered in laminated reservoirs. Commonly, a laminated reservoir comprises thin sand and shale layers while the seal for the reservoir is a thick shale. In such cases, the method described by Landro may encounter problems for several reasons. One reason is that attributing the entire change in the reflectivity of seismic waves (even when the effects of pore pressure changes are small) to fluid saturation changes in the reservoir can lead to errors because the fluid saturation changes occur predominantly in the sands and not in the shale. A second reason is that a laminated sequence exhibits transverse isotropy and the AVO behavior of seismic reflections may not be accurately described by the standard form of the Zoeppritz equations that were derived for plane interfaces between two isotropic half spaces. As would be known to those versed in the art, in a transversely isotropic (TI) medium, there is a single symmetry axis and the medium has a complete rotational symmetry about the axis. The properties of the medium in a plane normal to the symmetry axis do not change with direction while they are different from properties along the symmetry axis. A laminated formation typically has a symmetry axis normal to the bedding plane.
There is a need for a method of determination of changes in reservoir conditions in laminated reservoirs. Such a method should preferably take into account the effect of fluid pressure changes as well as any possible anisotropy in the reservoir. The present invention satisfies this need.
The present invention is a method of determining changes in fluid saturation and/or pressure of a laminated reservoir. A multicomponent resistivity logging tool is used for obtaining resistivity measurements indicative of properties of the formation at a wellbore. These resistivity data in combination with other measurements described below are processed to give a petrophysical model of the reservoir at the wellbore. The petrophysical model produces a fluid saturation estimate for the sand component of the reservoir. Acoustic measurements at the wellbore, combined with the above resistivity log derived water saturation data, are then used to define the elastic properties of the reservoir at the wellbore. These are next extrapolated away from the well. Changes in the AVO characteristics of the reservoir over time are indicative of changes in the fluid saturation and/or the pressure. These changes in the AVO characteristics are interpreted assuming that all the fluid substitution takes place within the sand component of the reservoir.